U.S. patent number 11,279,870 [Application Number 16/703,804] was granted by the patent office on 2022-03-22 for cavitation of polymer-containing fluids for use in subterranean formations.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. The grantee listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Dale E. Jamison, Preston Andrew May, William Walter Shumway.
United States Patent |
11,279,870 |
May , et al. |
March 22, 2022 |
Cavitation of polymer-containing fluids for use in subterranean
formations
Abstract
Methods for breaking polymer-containing treatment fluids for use
in subterranean formations are provided. In one or more
embodiments, the methods include providing a treatment fluid
comprising a base fluid and a polymer, wherein the treatment fluid
was recovered from at least a portion of a subterranean formation
located at a wellsite; transporting the treatment fluid from the
wellsite to an off-site location; and applying a cavitation
technique to at least a portion of the treatment fluid at the
off-site location.
Inventors: |
May; Preston Andrew (Porter,
TX), Shumway; William Walter (Spring, TX), Jamison; Dale
E. (Humble, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc. (Houston, TX)
|
Family
ID: |
1000006191359 |
Appl.
No.: |
16/703,804 |
Filed: |
December 4, 2019 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20210171825 A1 |
Jun 10, 2021 |
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
B01D
21/283 (20130101); C09K 8/885 (20130101); C09K
8/882 (20130101); E21B 21/065 (20130101) |
Current International
Class: |
C09K
8/68 (20060101); C09K 8/88 (20060101); B01D
21/28 (20060101); E21B 21/06 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
|
|
|
|
|
|
|
0164225 |
|
Dec 1985 |
|
EP |
|
10-2010-0009968 |
|
Jan 2010 |
|
KR |
|
2004/092534 |
|
Oct 2004 |
|
WO |
|
2010/012032 |
|
Feb 2010 |
|
WO |
|
2010065603 |
|
Jun 2010 |
|
WO |
|
2017/083951 |
|
May 2017 |
|
WO |
|
Other References
Reference Guide downloaded on Mar. 22, 2021. cited by examiner
.
Pawar (I. A. Pawar et al., Ultrasound-based treatment approaches
for intrinsic viscosity reduction of polyvinyl pyrrolidone (PVP),
Ultrasonics Sonochemistry, 21, 2014, 1108-1116). cited by examiner
.
International Search Report and Written Opinion issued in related
PCT Application No. PCT/US2019/064675 dated Aug. 28, 2020, 14
pages. cited by applicant.
|
Primary Examiner: Bhushan; Kumar R
Attorney, Agent or Firm: Krueger; Tenley Baker Botts
L.L.P.
Claims
What is claimed is:
1. A method comprising: providing a treatment fluid comprising a
base fluid, at least one polymer, and one or more solid
particulates, wherein the at least one polymer is selected from the
group consisting of: guar, hydroxyethyl guar, hydroxypropyl guar,
carboxymethyl guar, carboxymethylhydroxyethyl guar,
carboxymethylhydroxypropyl guar, cellulose, hydroxyethyl cellulose,
carboxyethylcellulose, carboxymethylcellulose,
carboxymethylhydroxyethylcellulose, xanthan, scleroglucan, diutan,
welan gum, alginate, starch, carboxymethyl starch,
poly(styrene-butadiene), poly(styrene-acrylate),
poly(styrene-sulfonate), polyethylene, polypropylene, polyethylene
glycol, polypropylene glycol, polyvinyl alcohol, polyvinylchloride,
polyvinylpyrrolidone, poly(2-acrylamido-2-methyl-1-propanesulfonic
acid), polyacrylate, partially hydrolyzed polyacrylate,
polysulfone, poly(ethersulfone), polyetherimide, poly(phenylene
sulfide), polyetheretherketone, polyether ketones, a fluoropolymer,
any derivative thereof, and any combination thereof; applying a
cavitation technique to the treatment fluid to break the at least
one polymer thereby reducing a viscosity of the treatment fluid,
wherein the cavitation technique is applied to the treatment fluid
outside of a wellbore penetrating a subterranean formation; and
separating or removing at least a portion of the one or more solid
particulates from the treatment fluid using a separation or removal
technique selected from the group consisting of: settling,
decantation, centrifugation, dissolving, dissolution, and any
combination thereof.
2. The method of claim 1, wherein the one or more solid
particulates are selected from the group consisting of: a bridging
agent, a lost circulation material, and any combination
thereof.
3. The method of claim 1 further comprising: adding one or more
additives to the treatment fluid after the portion of the one or
more solid particulates has been separated or removed to form a
second treatment fluid; and introducing the second treatment fluid
into at least a portion of a subterranean formation.
4. The method of claim 1, wherein applying the cavitation technique
to the treatment fluid comprises using a device selected from the
group consisting of: a hydrodynamic cavitation device, a
centrifugal pump, a marine propeller, a water turbine, an
ultrasonic probe, an ultrasonic horn, an ultrasonic vibrator, an
ultrasonic homogenizer, a flow-through sonication device, and any
combination thereof.
5. The method of claim 1, wherein applying the cavitation technique
does not substantially alter a moisture content of the treatment
fluid.
6. A method comprising: providing a treatment fluid comprising a
brine and a polymer selected from the group consisting of:
poly(styrene-acrylate), poly(styrene-sulfonate), polyethylene,
polypropylene, polyvinyl alcohol, polyvinylchloride,
polyvinylpyrrolidone, poly(2-acrylamido-2-methyl-1-propanesulfonic
acid), polyacrylate, partially hydrolyzed polyacrylate, a
fluoropolymer, any derivative thereof, and any combination thereof,
wherein the treatment fluid was used to treat at least a portion of
a subterranean formation, and wherein the treatment fluid has a
first density from about 7 lb/gal to about 18 lb/gal; and applying
a cavitation technique to at least a portion of the treatment
fluid, wherein the cavitation technique induces cavitation in the
portion of the treatment fluid, and wherein the cavitation
technique is applied to the portion of the treatment fluid outside
of the subterranean formation.
7. The method of claim 6, wherein the treatment fluid has a second
density after applying the cavitation technique that is from about
90% to about 100% of the first density.
8. The method of claim 6, wherein the polymer has a molecular
weight equal to or greater than about 30,000 g/mol.
9. The method of claim 6, wherein applying the cavitation technique
to at least the portion of the treatment fluid comprises using a
device selected from the group consisting of: a hydrodynamic
cavitation device, a centrifugal pump, a marine propeller, a water
turbine, an ultrasonic probe, an ultrasonic horn, an ultrasonic
vibrator, an ultrasonic homogenizer, a flow-through sonication
device, and any combination thereof.
10. The method of claim 6, wherein applying the cavitation
technique does not substantially alter a moisture content of the
treatment fluid.
11. The method of claim 6, wherein the treatment fluid further
comprises one or more solid particulates, and wherein the method
further comprises separating or removing at least a portion of the
one or more solid particulates from the treatment fluid.
12. The method of claim 11, wherein the portion of the one or more
solid particulates is separated or removed from the treatment fluid
using a separation or removal technique selected from the group
consisting of: settling, decantation, filtration, centrifugation,
dissolving, dissolution, and any combination thereof.
13. A method comprising: providing at least a portion of a
treatment fluid comprising a base fluid and a polymer having a
molecular weight equal to or greater than about 30,000 g/mol,
wherein the treatment fluid was recovered from a subterranean
formation located at a wellsite; transporting the treatment fluid
from the wellsite to an off-site location; applying a cavitation
technique to the portion of the treatment fluid at the off-site
location to break at least a portion of the polymer thereby
reducing a viscosity of the portion of the treatment fluid, adding
one or more additives to the portion of the treatment fluid
comprising the broken polymer to form a second treatment fluid; and
introducing the second treatment fluid into at least a portion of a
second subterranean formation.
14. The method of claim 13, wherein applying the cavitation
technique to at least the portion of the treatment fluid comprises
using a device selected from the group consisting of: a
hydrodynamic cavitation device, a centrifugal pump, a marine
propeller, a water turbine, an ultrasonic probe, an ultrasonic
horn, an ultrasonic vibrator, an ultrasonic homogenizer, a
flow-through sonication device, and any combination thereof.
15. The method of claim 13 further comprising storing the treatment
fluid at the off-site location.
16. The method of claim 13, wherein the treatment fluid further
comprises one or more solid particulates, and wherein the method
further comprises separating or removing at least a portion of the
one or more solid particulates from the treatment fluid using a
separation or removal technique selected from the group consisting
of: settling, decantation, filtration, centrifugation, dissolving,
dissolution, and any combination thereof.
17. The method of claim 16, wherein the portion of the one or more
solid particulates is separated or removed at the off-site
location.
18. The method of claim 13, wherein the one or more additives are
added to the treatment fluid at the off-site location.
Description
BACKGROUND
The present disclosure relates to methods for breaking
polymer-containing treatment fluids for use in subterranean
formations.
Treatment fluids can be used in a variety of subterranean treatment
operations. As used herein, the terms "treat," "treatment,"
"treating," and grammatical equivalents thereof refer to any
subterranean operation that uses a fluid in conjunction with
achieving a desired function and/or for a desired purpose. Use of
these terms does not imply any particular action by the treatment
fluid. Illustrative treatment operations can include, for example,
drilling, fracturing, competition, and the like.
For example, while drilling an oil or gas well, a drilling fluid
(or drilling mud) is typically pumped down to a drill bit during
drilling operations and flowed back to the surface through an
annulus defined between a drill string and the walls of the
wellbore. Drilling fluids often include viscosifiers to, for
example, improve the ability of the drilling fluid to remove
cuttings from the wellbore and suspend cuttings.
Drill-in fluids are specially designed for drilling through a
subsurface hydrocarbon reservoir portion of a wellbore. Such fluids
are generally formulated to minimize formation damage and maximize
production of the zones exposed by the drilling. Like drilling
fluids, drill-in fluids generally include polymers for providing
viscosity, suspension, and fluid loss control.
Many polymers used in drilling fluids, drill-in fluids, and other
subterranean treatment fluids have been designed to be stable under
the extreme conditions of subterranean formations, such as high
temperatures and high pressures. After the desired application of a
treatment fluid has been achieved, it is often desirable to reduce
the viscosity of the fluid. Reducing the viscosity of a fluid may
be referred to as "breaking" the fluid. Breaking of fluids has been
accomplished using chemical breakers. However, the robust nature of
the polymers typically used in high temperature drilling and
drill-in fluids may be difficult to break with certain chemical
breakers, particularly at the surface at relatively low
temperatures and pressures.
BRIEF DESCRIPTION OF THE DRAWINGS
These drawings illustrate certain aspects of some of the
embodiments of the present disclosure and should not be used to
limit or define the claims.
FIG. 1 is a diagram illustrating an example of a drilling assembly
that may be used in accordance with certain embodiments of the
present disclosure.
FIG. 2 is a diagram illustrating an example of a fluid processing
operation that may be used in accordance with certain embodiments
of the present disclosure.
While embodiments of this disclosure have been depicted, such
embodiments do not imply a limitation on the disclosure, and no
such limitation should be inferred. The subject matter disclosed is
capable of considerable modification, alteration, and equivalents
in form and function, as will occur to those of ordinary skill in
the pertinent art and having the benefit of this disclosure. The
depicted and described embodiments of this disclosure are examples
only, and not exhaustive of the scope of the disclosure.
DESCRIPTION OF CERTAIN EMBODIMENTS
Illustrative embodiments of the present disclosure are described in
detail herein. In the interest of clarity, not all features of an
actual implementation may be described in this specification. It
will of course be appreciated that in the development of any such
actual embodiment, numerous implementation-specific decisions may
be made to achieve the specific implementation goals, which may
vary from one implementation to another. Moreover, it will be
appreciated that such a development effort might be complex and
time-consuming but would nevertheless be a routine undertaking for
those of ordinary skill in the art having the benefit of the
present disclosure.
The present disclosure relates to methods for breaking
polymer-containing treatment fluids for use in subterranean
formations. More specifically, the present disclosure provides
methods for breaking polymer-containing treatment fluids for use in
subterranean formations using cavitation to reclaim or recycle the
base fluids of the treatment fluids. In certain embodiments, the
methods of the present disclosure include providing a treatment
fluid including a base fluid and at least one polymer and
cavitating at least a portion of the treatment fluid with one or
more cavitation devices to at least partially reduce the viscosity
and/or suspension properties of the treatment fluid. In some
embodiments, the treatment fluid may also include (e.g., have
suspended therein) at least one solid, such as a bridging agent. In
certain embodiments, the treatment fluids used in the methods of
the present disclosure may be used or have been used to treat a
subterranean formation (e.g., as a drilling fluid or a drill-in
fluid) prior to cavitation. In certain embodiments, the treatment
fluids used in the methods of the present disclosure may be removed
from at least a portion of subterranean formation prior to
cavitation. In certain embodiments, the methods of the present
disclosure also may include applying a separation or removal
technique to the treatment fluid to substantially separate the base
fluid of the treatment fluid from the other components of the
treatment fluid (e.g., solid particulates).
Those of ordinary skill in the art having the benefit of the
present disclosure will appreciate the types of treatment fluids
including a base fluid and one or more polymers disclosed herein
that may be used in accordance with the methods of the present
disclosure. Examples of such treatment fluids include, but are not
limited to, drill-in fluids, drilling fluids, completion fluids,
workover fluids, fracturing fluids, acidizing fluids, suspension
fluids, breaker fluids, packer fluids, logging fluids, spacer
fluids, transition fluids, and the like. In certain embodiments,
the treatment fluids of the present disclosure may include any base
fluid known in the art, including aqueous base fluids, non-aqueous
base fluids, and any combinations thereof. The term "base fluid"
refers to the major component of the fluid (as opposed to
components dissolved and/or suspended therein) and does not
indicate any particular condition or property of that fluids such
as its mass, amount, pH, etc. Examples of non-aqueous fluids that
may be suitable for use in the methods and systems of the present
disclosure include, but are not limited to, oils, hydrocarbons,
organic liquids, and the like. In certain embodiments, the base
fluid may be an oil-in-water emulsion or a water-in-oil
emulsion.
Aqueous base fluids that may be suitable for use in the methods of
the present disclosure may include water from any source. Such
aqueous base fluids may include fresh water, salt water (e.g.,
water containing one or more salts dissolved therein), brine (e.g.,
saturated salt water), seawater, or any combination thereof. In
some embodiments, the aqueous base fluids may include one or more
ionic species, such as those formed by salts dissolved in water.
For example, seawater and/or produced water may include a variety
of divalent cationic species dissolved therein. The ionic species
may be any suitable ionic species known in the art. In certain
embodiments, the ionic species may be one or more salts selected
from the group consisting of: sodium chloride, sodium bromide,
sodium iodide, sodium acetate, sodium formate, sodium citrate,
potassium chloride, potassium formate, potassium iodide, potassium
bromide, calcium chloride, calcium nitrate, calcium bromide,
calcium iodide, magnesium chloride, magnesium bromide, magnesium
sulfate, cesium formate, zinc chloride, zinc bromide, zinc iodide,
and any combination thereof. In certain embodiments, the density of
the aqueous base fluid can be adjusted to, among other purposes,
provide additional particulate transport and suspension. In certain
embodiments, the pH of the aqueous base fluid may be adjusted
(e.g., by a buffer or other pH adjusting agent) to a specific
level, which may depend on, among other factors, the types of
clays, acids, and other additives included in the fluid. One of
ordinary skill in the art with the benefit of this disclosure will
recognize when such density and/or pH adjustments are
appropriate.
In certain embodiments, the treatment fluids of the present
disclosure may include one or more polymers. In certain
embodiments, the polymers used in the methods of the present
disclosure may have a molecular weight equal to or greater than
about 30,000 g/mol. The polymers that may be suitable for use in
the treatment fluids and methods of the present disclosure include
any polymer that is capable of increasing the viscosity,
suspension, and/or filtration control of a fluid. In certain
embodiments, the polymers used in the treatment fluids of the
present disclosure may be a naturally-occurring polymer (or derived
therefrom), a synthetic polymer, and/or combinations thereof.
Examples of polymers that may be suitable for use in the treatment
fluids and methods of the present disclosure include, but are not
limited to, guar, guar derivatives (e.g., hydroxyethyl guar,
hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl
guar, and carboxymethylhydroxypropyl guar ("CMHPG")), cellulose,
cellulose derivatives (e.g., hydroxyethyl cellulose,
carboxyethylcellulose, carboxymethylcellulose, and
carboxymethylhydroxyethylcellulose), biopolymers (e.g., xanthan,
scleroglucan, diutan, welan gum, alginate, etc.), starches, starch
derivatives (e.g., carboxymethyl starch), poly(styrene-butadiene),
poly(styrene-acrylate), poly(styrene-sulfonate), polyethylene,
polypropylene, polyethylene glycol, polypropylene glycol, polyvinyl
alcohol, polyvinylchloride, polylactic acid, polyacrylamide,
polyvinylpyrrolidone, poly(2-acrylamido-2-methyl-1-propanesulfonic
acid), polyacrylate, partially hydrolyzed polyacrylate, polysulfone
(PSU), poly(ethersulfone) (PES), polyetherimide (PEI),
poly(phenylene sulfide) (PPS), polyetheretherketone (PEEK),
polyether ketones (PEK), fluoropolymers, polyethylene glycol,
polypropylene glycol, any homopolymers thereof, any copolymers
thereof, any tetrapolymers thereof, any crosslinked versions
thereof, and/or combinations thereof. Examples of polymers that may
be suitable for use in the treatment fluids and methods of the
present disclosure include a xanthan polymer commercially available
from Halliburton Energy Services, Inc., of Houston, Tex., under the
trade name "N-VIS.RTM.;" a hydroxyethyl cellulose polymer
commercially available from Halliburton Energy Services, Inc., of
Houston, Tex., under the trade name "LIQUI-VIS.RTM. EP;" and a
crosslinked starch polymer commercially available from Halliburton
Energy Services, Inc., of Houston, Tex., under the trade name
"N-DRIL.TM. HT PLUS.TM.." In certain embodiments, the polymers may
be "crosslinked" with a crosslinking agent to, among other reasons,
impart enhanced viscosity and/or suspension properties to the
fluid.
In certain embodiments, other breaking techniques (such as applying
heat or adding a chemical breaker) may not substantially break the
polymers used in the treatment fluids and methods of the present
disclosure. In certain embodiments, the polymers used in the
methods of the present disclosure may withstand temperature above
about 350.degree. F. for over 30 days without substantially
breaking. As used herein, the term "substantially" means that at
least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%,
99.5%, 99.9%, 99.99%, alternatively at least about 99.999% or more,
of the polymer remains unbroken. Examples of such polymers that do
not substantially break under increased temperature and/or using
chemical breakers include, but are not limited to,
poly(styrene-acrylate), poly(styrene-sulfonate), polyethylene,
polypropylene, polyethylene glycol, polypropylene glycol, polyvinyl
alcohol, polyvinylchloride, polyvinylpyrrolidone,
poly(2-acrylamido-2-methyl-1-propanesulfonic acid), polyacrylate,
partially hydrolyzed polyacrylate, polysulfone (PSU),
poly(ethersulfone) (PES), polyetherimide (PEI), poly(phenylene
sulfide) (PPS), polyetheretherketone (PEEK), polyether ketones
(PEK), fluoropolymers, any derivative thereof, and any combination
thereof. Thus, in certain embodiments, cavitation may be necessary
to break these polymers.
The polymers may be included in any amount sufficient to impart the
desired viscosity, suspension, and/or filtration control properties
to the fluid. In certain embodiments, the one or more polymers may
be included in an amount of from about 0.1 pounds per barrel
(lb/bbl) of the treatment fluid to about 20 lb/bbl of the treatment
fluid. In other embodiments, the one or more polymers may be
included in an amount of from about 1 lb/bbl of the treatment fluid
to about 15 lb/bbl of the treatment fluid. In other embodiments,
the one or more polymers may be included in an amount of from about
2 lb/bbl of the treatment fluid to about 10 lb/bbl of the treatment
fluid. In other embodiments, the one or more polymers may be
included in an amount of from about 0.5 lb/bbl of the treatment
fluid to about 5 lb/bbl of the treatment fluid. In other
embodiments, the one or more polymers may be included in an amount
of from about 1 lb/bbl of the treatment fluid to about 8 lb/bbl of
the treatment fluid.
In other embodiments, the one or more polymers may be included in
an amount of less than about 20 lb/bbl. In other embodiments, the
one or more polymers may be included in an amount of less than
about 15 lb/bbl. In other embodiments, the one or more polymers may
be included in an amount of less than about 12 lb/bbl. In other
embodiments, the one or more polymers may be included in an amount
of less than about 10 lb/bbl. In other embodiments, the one or more
polymers may be included in an amount of less than about 8
lb/bbl.
In certain embodiments, the treatment fluids of the present
disclosure may include one or more lost circulation materials or
bridging agents. In certain embodiments, lost circulation materials
or bridging agents may include, but are not limited to,
BARACARB.RTM. particulates (ground marble, available from
Halliburton Energy Services, Inc.) including BARACARB.RTM. 5,
BARACARB.RTM. 25, BARACARB.RTM. 50, BARACARB.RTM. 150,
BARACARB.RTM. 600, BARACARB.RTM. 1200; STEELSEAL.RTM. particulates
(resilient graphitic carbon, available from Halliburton Energy
Services, Inc.) including STEELSEAL.RTM. powder, STEELSEAL.RTM. 50,
STEELSEAL.RTM. 150, STEELSEAL.RTM. 400 and STEELSEAL.RTM. 1000;
WALL-NUT.RTM. particulates (ground walnut shells, available from
Halliburton Energy Services, Inc.) including WALL-NUT.RTM. M,
WALL-NUT.RTM. coarse, WALL-NUT.RTM. medium, and WALL-NUT.RTM. fine;
BARAPLUG.RTM. (sized salt water, available from Halliburton Energy
Services, Inc.) including BARAPLUG.RTM. 20, BARAPLUG.RTM. 50, and
BARAPLUG.RTM. 3/300; BARAFLAKE.RTM. (calcium carbonate and
polymers, available from Halliburton Energy Services, Inc.); acid
soluble bridging solids including magnesium and calcium carbonate,
limestone, marble, dolomite, iron carbonate, iron oxide, calcium
oxide, magnesium oxide, perborate salts and the like; and any
combination thereof.
In certain embodiments, the treatment fluids of the present
disclosure may include any number of additives. Examples of such
additives include, but are not limited to, salts, surfactants,
acids, diverting agents, fluid loss control additives, gas,
nitrogen, carbon dioxide, surface modifying agents, tackifying
agents, foamers, corrosion inhibitors, scale inhibitors, catalysts,
clay stabilizers, shale inhibitors, biocides, friction reducers,
antifoam agents, additional bridging agents, flocculants, H.sub.2S
scavengers, CO.sub.2 scavengers, oxygen scavengers, lubricants,
hydrocarbons, additional viscosifying/gelling agents, breakers,
weighting agents, relative permeability modifiers, resins, wetting
agents, coating enhancement agents, filter cake removal agents,
antifreeze agents (e.g., ethylene glycol), particulates, and the
like. A person skilled in the art, with the benefit of this
disclosure, will recognize the types of additives that may be
included in the treatment fluids of the present disclosure for a
particular application. In certain embodiments, the treatment
fluids used in the methods of the present disclosure may be used or
have been used to treat a subterranean formation (e.g., as a
drilling fluid or drill-in fluid).
Thus, the treatment fluids may also include solid particulates,
such as lost circulation materials, bridging agents, solid
breakers, internal breakers, proppant, solid alkalinity control
agents, solids from the subterranean formation (e.g., rock
fragments generated by the drill bit during drilling), and any
combination thereof. In certain embodiments, the size of the solid
particulates may be in the range from about 0.1 micron to about 100
microns. In other embodiments, the size of the solid particulates
may be in the range from about 1 micron to about 200 microns. In
other embodiments, the size of the solid particulates may be in the
range from about 2 microns to about 600 microns. In other
embodiments, the size of the solid particulates may be in the range
from about 5 microns to about 600 microns. In other embodiments,
the size of the solid particulates may be in the range from about
25 microns to about 400 microns. In other embodiments, the size of
the solid particulates may be in the range from about 2 microns to
about 1200 microns.
In certain embodiments, the methods of the present disclosure
include applying a cavitation technique to at least a portion of
the treatment fluids of the present disclosure. In one or more
embodiments, applying a cavitation technique to the treatment
fluids may cause the formation of cavities (e.g., "bubbles" or
"voids") in the treatment fluid (e.g., direct cavitation) or
another fluid in proximity to the treatment fluid (e.g., indirect
cavitation) that may collapse and generate a shock wave. In certain
embodiments, the shock wave may have sufficient energy to at least
partially break (e.g., via chain scission) the polymer. Thus,
applying a cavitation technique to the treatment fluids of the
present disclosure may at least partially reduce the viscosity
and/or suspension properties of the treatment fluids by at least
partially "breaking" the polymer in the fluid.
In certain embodiments, the treatment fluid may have a density from
about 7 lb/gal to about 18 lb/gal prior to applying the cavitation
technique to the fluid. In other embodiments, the treatment fluid
may have a density from about 8 lb/gal to about 17 lb/gal prior to
applying the cavitation technique to the fluid. In other
embodiments, the treatment fluid may have a density from about 12
lb/gal to about 16 lb/gal prior to applying the cavitation
technique to the fluid. In certain embodiments, applying a
cavitation technique to the treatment fluid does not substantially
alter (increase or decrease) the density of the fluid. In certain
embodiments, applying a cavitation technique to the treatment fluid
does not substantially alter (increase or decrease) the moisture
content of the fluid. In some embodiments, applying a cavitation
technique to the treatment fluid does not substantially concentrate
the treatment fluid. As used herein, the term "moisture content"
refers to the quantity of the base fluid in the treatment fluid. As
used herein, the term "substantially" means that the density and/or
the moisture content of the fluid remains at least about 50%, 60%,
70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%,
alternatively at least about 99.999% or more, of the original
value. In certain embodiments, the treatment fluid may have a
density from about 7 lb/gal to about 18 lb/gal after applying the
cavitation technique to the fluid. In other embodiments, the
treatment fluid may have a density from about 8 lb/gal to about 17
lb/gal after applying the cavitation technique to the fluid. In
other embodiments, the treatment fluid may have a density from
about 12 lb/gal to about 16 lb/gal after applying the cavitation
technique to the fluid.
In certain embodiments, one or more cavitation techniques may be
applied to the treatment fluids of the present disclosure. Examples
of cavitation techniques that may be suitable for use in the
methods of the present disclosure include, but are not limited to,
hydrodynamic cavitation, ultrasonic induced cavitation (e.g., via
sonication), and any combination thereof. Examples of cavitation
devices that may be suitable for use in the methods of the present
disclosure include, but are not limited to, hydrodynamic cavitation
devices, centrifugal pumps, marine propellers, water turbines,
ultrasonic probes, ultrasonic horns, ultrasonic vibrators,
ultrasonic homogenizers, flow-through sonication devices, and any
combination thereof. Those of ordinary skill in the art having the
benefit of the present disclosure will appreciate such devices may
be modified to induce and/or increase cavitation by, for example,
including lowering the viscosity of the fluid (e.g., with chemicals
and/or heat), adding low pressure regions to the cavitation device
(e.g., near impellers or propellers), increasing the pressure in
the cavitation device, increasing the flowrate of the treatment
fluid through the device and/or the speed of the device, and any
combination thereof. Those of ordinary skill in the art having the
benefit of the present disclosure will appreciate other cavitation
techniques and devices that may be used in accordance with the
methods of the present disclosure. In certain embodiments, multiple
cavitation techniques (either the same or different) may be applied
to the fluid in parallel or series.
In certain embodiments, additional methods for reducing the
viscosity of the treatment fluid may also be utilized in addition
to cavitating the fluid. Such additional methods include, but are
not limited to, applying pressure and/or heat to the treatment
fluid and adding chemical breakers to the treatment fluid. In such
embodiments, chemical breakers may be added before, after, and/or
during cavitation. In some embodiments, the chemical breaker may be
ineffective in sufficiently breaking the polymers in the treatment
fluid on its own. However, it may aid in breaking the polymers in
the treatment fluid before, after, and/or during cavitation. In
some embodiments, the cavitation may make the chemical breaker more
effective. In some embodiments, the chemical breaker may not impact
or impede the cavitation. In certain embodiments, the cavitation of
the treatment fluid may be performed at ambient temperature and/or
pressure. In certain embodiments, other chemicals may be added to
the fluid to aid in cavitating the fluid (e.g., through chemical
oxidation). Examples of such chemical include ozone, carbon
dioxide, oxygen, peroxides (e.g., hydrogen peroxide), nitric acid,
sulfuric acid, peroxydisulfuric acid, peroxymonosulfuric acid,
chlorite, chlorate, perchlorate, hypochlorite, pyridinium
chlorochromate, permanganate compounds, perborate compounds,
nitrous oxide, nitrogen dioxide, potassium nitrate, and any
combination thereof. In certain embodiments, the methods of the
present disclosure do not use ozone, carbon dioxide, and/or
chemical oxidation in connection with the cavitation technique. In
certain embodiments, ozone and/or carbon dioxide is not added to
the fluid before or during cavitation.
In certain embodiments, the treatment fluid may be cavitated (e.g.,
exposed to one or more cavitation techniques) for a sufficient
length of time to cause cavitation of the treatment fluid and/or
achieve a desire reduction in the viscosity and/or suspension
properties of the treatment fluid. In certain embodiments, the
treatment fluid may be cavitated for a time in a range of about 1
second to about 10 minutes. In other embodiments, the treatment
fluid may be cavitated for a time greater than about 10 minutes.
Those of ordinary skill in the art having the benefit of the
present disclosure will appreciate that the residence time for a
given volume of the treatment fluid in the flow-through cavitation
device would be dictated by the flow rate of the fluid. Those of
ordinary skill in the art having the benefit of the present
disclosure will appreciate that any volume of treatment fluid may
be cavitated using the methods of the present disclosure and that
the residence time in a cavitated device may be impacted by the
volume of the fluid.
In certain embodiments, the treatment fluids may be cooled while
the cavitation technique is applied to mitigate at least a portion
of the heat generating during the cavitation. In certain
embodiments, the treatment fluids may be allowed to sit static for
a period of time after applying the cavitation technique to, among
other reasons, allow the reduction in the viscosity and/or
suspension properties of the fluid to occur and/or to allow the
components in the fluid (e.g., bridging agents) to settle and/or
separate from the base fluid.
In certain embodiments, the methods of the present disclosure also
may include the use of one or more separation or removal techniques
on the treatment fluids to separate the base fluid (e.g., brine)
from solid component of the fluid (e.g., lost circulation materials
and bridging agents). Examples of techniques that may be suitable
for removing or separating solid particulates from the treatment
fluid in accordance with the methods of the present disclosure
include, but are not limited to, settling, decantation, filtration,
centrifugation, dissolution or dissolving (e.g., with acid),
electrocoagulation, and any combination thereof. Those of ordinary
skill in the art having the benefit of the present disclosure will
appreciate that the separation or removal techniques used may
depend on, among other things, the size of the solid particulates
being removed or separated from the base fluid. In certain
embodiments, the solid particulates may be large enough that
filtration is not as desirable as other separation techniques
(e.g., settling). In other embodiments, the solid particulates may
be small enough that filtration is not as desirable as other
separation techniques (e.g., dissolution or centrifugation). In
certain embodiments, the methods of the present disclosure also may
include the use of other separation techniques (e.g., distillation)
to remove other components (e.g., salts) from the base fluid. Those
of ordinary skill in the art having the benefit of the present
disclosure will appreciate other separation or removal techniques
that may be used in accordance with the methods of this
disclosure.
In certain embodiments, the base fluid (e.g., brine) of the
treatment fluid may be recovered following the cavitation
technique(s) and/or the separation or removal technique(s). In such
embodiments, the recovered base fluid may be recycled or reused.
For example, in certain embodiments, the recovered base fluid may
be introduced into a subterranean formation and/or a wellbore
penetrating a subterranean formation. In such embodiments,
additional additives, such as those disclosed herein, may be added
to the recovered base fluid before it is introduced into the
subterranean formation and/or the wellbore. In some embodiments,
the recovered base fluid may be blended with a fresh based fluid
(e.g., a fluid that has not yet been used to treat a subterranean
formation) before it is introduced into the subterranean formation
and/or the wellbore. In such embodiments, less polymer may be
needed in the fresh based fluid because of the polymer remaining in
the reclaimed base fluid.
Some embodiments of the present disclosure provide methods for
using the disclosed treatment fluids to carry out a variety of
subterranean treatments, including but not limited to, drilling.
The drilling and/or drill-in fluids disclosed herein may directly
or indirectly affect one or more components or pieces of equipment
associated with the preparation, delivery, recapture, recycling,
reuse, and/or disposal of the drilling and/or drill-in fluids. For
example, and with reference to FIG. 1, the drilling and/or drill-in
fluids disclosed herein may directly or indirectly affect one or
more components or pieces of equipment associated with a wellbore
drilling assembly 100, according to one or more embodiments. It
should be noted that while FIG. 1 generally depicts a land-based
drilling assembly, those skilled in the art will readily recognize
that the principles described herein are equally applicable to
subsea drilling operations that employ floating or sea-based
platforms and rigs, without departing from the scope of the
disclosure.
As illustrated, the drilling assembly 100 may include a drilling
platform 102 that supports a derrick 104 having a traveling block
106 for raising and lowering a drill string 108. The drill string
108 may include, but is not limited to, drill pipe and coiled
tubing, as generally known to those skilled in the art. A kelly 110
supports the drill string 108 as it is lowered through a rotary
table 112. A drill bit 114 is attached to the distal end of the
drill string 108 and is driven either by a downhole motor and/or
via rotation of the drill string 108 from the well surface. As the
bit 114 rotates, it creates a borehole 116 that penetrates various
subterranean formations 118.
A pump 120 (e.g., a mud pump) circulates a drilling and/or drill-in
fluid 122 of the present disclosure through a feed pipe 124 and to
the kelly 110, which conveys the drilling and/or drill-in fluid 122
downhole through the interior of the drill string 108 and through
one or more orifices in the drill bit 114. The drilling and/or
drill-in fluid 122 may then circulated back to the surface via an
annulus 126 defined between the drill string 108 and the walls of
the borehole 116. At the surface, one or more fluid processing
unit(s) 128 via an interconnecting flow line 130. After passing
through the fluid processing unit(s) 128, a "cleaned" drilling
and/or drill-in fluid 122 is deposited into a nearby retention pit
132 (i.e., a mud pit). In certain embodiments, the cavitation
technique(s) and/or the separation or removal technique(s) disclose
herein may be performed in the fluid processing unit(s) 128.
While illustrated in FIG. 1 as being arranged at the outlet of the
wellbore 116 via the annulus 126, those skilled in the art will
readily appreciate that the fluid processing unit(s) 128 may be
arranged at any other location in the drilling assembly 100, any
other wellsite location, or an off-site location to facilitate its
proper function, without departing from the scope of the
disclosure. For example, as shown in FIG. 2, in certain
embodiments, the spent drilling and/or drill-in fluid 122 may be
transported to an off-site location 200 from the wellsite 220. In
such embodiments, the spent drilling and/or drill-in fluid 122
exits the annulus 126 and may be conveyed to one or more tanks or
vessels 202. The tanks or vessels 202 may be loaded onto a truck
218 and transported to the off-site location 200 for processing in
accordance with the methods of the present disclosure. In certain
embodiments, the spent drilling and/or drill-in fluid 122 may be
transferred from the tanks or vessels 202 to a cavitation device
204 disclosed herein. Although not pictured, depending upon the
cavitation technique utilized in accordance with the methods of the
present disclosure, the cavitation device 204 may instead be added
to the tanks or vessels 202. In some embodiments, the spent
drilling and/or drill-in fluid 122 may be stored at the off-site
location 200 in the tanks or vessels 202 (or another tank or
vessel) for a period of time (e.g., from about a week to about a
year or more) prior contacting the fluid 122 with the cavitation
device 204.
In some embodiments, a precipitant may optionally be added to the
spent drilling and/or drill-in fluid 122 to further "clean" the
fluid. In such embodiments, the precipitant may be allowed to form
a precipitate with at least a portion of the polymer in the spent
drilling and/or drill-in fluid 122. As shown in FIG. 2, the spent
drilling and/or drill-in fluid 122 may be transferred from the
cavitation device to a tank 206. In some embodiments, the tank 206
may be a mixing tank and may contain a mixing device 208 (e.g.,
impeller, agitator, stirring rod, jet). Although not pictured, in
some embodiments, the precipitant may be added to the spent
drilling and/or drill-in fluid 122 in the tank or vessel 202 or in
the cavitation device 204 instead of utilizing the tank 206. In
certain embodiments, after the precipitant is allowed to form a
precipitate with at least a portion of the polymer to the spent
drilling and/or drill-in fluid 122, the fluid may be transferred to
a separation apparatus 210 (e.g., a settler, a decanter, a filter,
a centrifuge, a tank) to remove at least a portion of the
precipitate. As noted above, the use of a precipitant is optional.
Thus, in some embodiments, a precipitant may not be used to further
"clean" the fluid the spent drilling and/or drill-in fluid 122. In
such embodiments, neither tank 206 nor separation apparatus 210
would be required and the spent drilling and/or drill-in fluid 122
may be transferred from cavitation device 204 to a separation or
removal apparatus 212.
In certain embodiments, the spent drilling and/or drill-in fluid
122 with the polymer at least partially broken (and optionally
removed following precipitation with the precipitate) may then be
transferred to a separation or removal apparatus 212 (e.g., a
settler, a decanter, a filter, a centrifuge, a tank), as discussed
above, to remove at least a portion of the solid particulates
(e.g., lost circulation materials and bridging agents) in the
fluid. Although not pictured, in other embodiments, the spent
drilling and/or drill-in fluid 122 may be transferred to a
separation or removal apparatus 212 to remove at least a portion of
the solid particulates in the fluid prior to the application of the
cavitation technique. The final "cleaned" drilling and/or drill-in
fluid (e.g., the aqueous base fluid) may be stored in one or more
tanks or vessels 214 for a period of time (e.g., from about a week
to about a year or more) at the off-site location 200. The tanks or
vessels 214 may be loaded onto a truck 216 and transported to back
to the wellsite 220, which may be the same wellsite from which the
spent drilling and/or drill-in fluid 122 was taken or a different
wellsite.
Returning back to FIG. 1, once the cleaned fluid is back at the
wellsite, one or more components disclosed herein (e.g.,
viscosifiers, lost circulation materials, and bridging agents) may
be added to the "cleaned" drilling and/or drill-in fluid 122 via a
mixing hopper 134 communicably coupled to or otherwise in fluid
communication with the retention pit 132. The mixing hopper 134 may
include, but is not limited to, mixers and related mixing equipment
known to those skilled in the art. In other embodiments, however,
the components may be added to the drilling and/or drill-in fluid
122 at any other location in the drilling assembly 100, any other
wellsite location, or an off-site location to facilitate its proper
function. In at least one embodiment, for example, there could be
more than one retention pit 132, such as multiple retention pits
132 in series. Moreover, the retention pit 132 may be
representative of one or more fluid storage facilities and/or units
where the drilling and/or drill-in fluid 122 or any component
thereof (e.g., base fluid or brine) may be stored, reconditioned,
and/or regulated until recycled or reused.
As mentioned above, the drilling and/or drill-in fluid 122 of the
present disclosure may directly or indirectly affect the components
and equipment of the drilling assembly 100. For example, the
disclosed drilling and/or drill-in fluid 122 may directly or
indirectly affect the fluid processing unit(s) 128 which may
include, but is not limited to, one or more of a shaker (e.g.,
shale shaker), a centrifuge, a hydrocyclone, a separator (including
magnetic and electrical separators), a desilter, a desander, a
filter (e.g., diatomaceous earth filters), a heat exchanger, and/or
any fluid reclamation equipment. The fluid processing unit(s) 128
may further include one or more sensors, gauges, pumps,
compressors, and the like used to store, monitor, regulate, and/or
recondition the drilling and/or drill-in fluid 122.
The drilling and/or drill-in fluid 122 of the present disclosure
may directly or indirectly affect the pump 120, which
representatively includes any conduits, pipelines, trucks,
tubulars, and/or pipes used to fluidically convey the drilling
and/or drill-in fluid 122 downhole, any pumps, compressors, or
motors (e.g., topside or downhole) used to drive the drilling
and/or drill-in fluid 122 into motion, any valves or related joints
used to regulate the pressure or flow rate of the drilling and/or
drill-in fluid 122, and any sensors (i.e., pressure, temperature,
flow rate, etc.), gauges, and/or combinations thereof, and the
like. The disclosed drilling and/or drill-in fluid 122 may also
directly or indirectly affect the mixing hopper 134 and the
retention pit 132 and their assorted variations.
The drilling and/or drill-in fluid 122 of the present disclosure
may also directly or indirectly affect the various downhole
equipment and tools that may come into contact with the drilling
and/or drill-in fluid 122 such as, but not limited to, the drill
string 108, any floats, drill collars, mud motors, downhole motors
and/or pumps associated with the drill string 108, and any MWD/LWD
tools and related telemetry equipment, sensors or distributed
sensors associated with the drill string 108. The disclosed
drilling and/or drill-in fluid 122 may also directly or indirectly
affect any downhole heat exchangers, valves and corresponding
actuation devices, tool seals, packers and other wellbore isolation
devices or components, and the like associated with the wellbore
116. The disclosed drilling and/or drill-in fluid 122 may also
directly or indirectly affect the drill bit 114, which may include,
but is not limited to, roller cone bits, PDC bits, natural diamond
bits, any hole openers, reamers, coring bits, etc.
While not specifically illustrated herein, the drilling and/or
drill-in fluid 122 of the present disclosure may also directly or
indirectly affect any transport or delivery equipment used to
convey the drilling and/or drill-in fluid 122 to the drilling
assembly 100 such as, for example, any transport vessels, conduits,
pipelines, trucks, tubulars, and/or pipes used to fluidically move
the drilling and/or drill-in fluid 122 from one location to
another, any pumps, compressors, or motors used to drive the
drilling and/or drill-in fluid 122 into motion, any valves or
related joints used to regulate the pressure or flow rate of the
drilling and/or drill-in fluid 122, and any sensors (i.e., pressure
and temperature), gauges, and/or combinations thereof, and the
like.
An embodiment of the present disclosure is a method including:
providing a treatment fluid comprising a base fluid, at least one
polymer, and one or more solid particulates; applying a cavitation
technique to at least a portion of the treatment fluid; and
separating or removing at least a portion of the solid particulates
from the treatment fluid using a separation or removal technique
selected from the group consisting of: settling, decantation,
centrifugation, dissolving, dissolution, and any combination
thereof.
In one or more embodiments described in the preceding paragraph,
wherein the one or more solid particulates are selected from the
group consisting of: a bridging agent, a lost circulation material,
and any combination thereof. In one or more embodiments described
in the preceding paragraph, adding one or more additives to the
treatment fluid after the portion of the solid particulates has
been separated or removed to form a second treatment fluid; and
introducing the second treatment fluid into at least a portion of
the subterranean formation. In one or more embodiments described in
the preceding paragraph, wherein applying the cavitation technique
to at least the portion of the treatment fluid comprises using a
device selected from the group consisting of: a hydrodynamic
cavitation device, a centrifugal pump, a marine propeller, a water
turbine, an ultrasonic probe, an ultrasonic horn, an ultrasonic
vibrator, an ultrasonic homogenizer, a flow-through sonication
device, and any combination thereof. In one or more embodiments
described in the preceding paragraph, wherein the polymer is
selected from the group consisting of: poly(styrene-acrylate),
poly(styrene-sulfonate), polyethylene, polypropylene, polyethylene
glycol, polypropylene glycol, polyvinyl alcohol, polyvinylchloride,
polyvinylpyrrolidone, poly(2-acrylamido-2-methyl-1-propanesulfonic
acid), polyacrylate, partially hydrolyzed polyacrylate,
polysulfone, poly(ethersulfone), polyetherimide, poly(phenylene
sulfide), polyetheretherketone, polyether ketones, a fluoropolymer,
any derivative thereof, and any combination thereof. In one or more
embodiments described in the preceding paragraph, wherein applying
the cavitation technique does not substantially alter a moisture
content of the treatment fluid.
An embodiment of the present disclosure is a method including:
providing a treatment fluid comprising a brine and a polymer
selected from the group consisting of: poly(styrene-acrylate),
poly(styrene-sulfonate), polyethylene, polypropylene, polyethylene
glycol, polypropylene glycol, polyvinyl alcohol, polyvinylchloride,
polyvinylpyrrolidone, poly(2-acrylamido-2-methyl-1-propanesulfonic
acid), polyacrylate, partially hydrolyzed polyacrylate,
polysulfone, poly(ethersulfone), polyetherimide, poly(phenylene
sulfide), polyetheretherketone, polyether ketones, a fluoropolymer,
any derivative thereof, and any combination thereof, wherein the
treatment fluid was used to treat at least a portion of a
subterranean formation, and wherein the treatment fluid has a first
density from about 7 lb/gal to about 18 lb/gal; and applying a
cavitation technique to at least a portion of the treatment
fluid.
In one or more embodiments described in the preceding paragraph,
wherein the treatment fluid has a second density after applying the
cavitation technique that is from about 90% to about 100% of the
first density. In one or more embodiments described in the
preceding paragraph, wherein the polymer has a molecular weight
equal to or greater than about 30,000 g/mol. In one or more
embodiments described in the preceding paragraph, wherein applying
the cavitation technique to at least the portion of the treatment
fluid comprises using a device selected from the group consisting
of: a hydrodynamic cavitation device, a centrifugal pump, a marine
propeller, a water turbine, an ultrasonic probe, an ultrasonic
horn, an ultrasonic vibrator, an ultrasonic homogenizer, a
flow-through sonication device, and any combination thereof. In one
or more embodiments described in the preceding paragraph, wherein
applying the cavitation technique does not substantially alter a
moisture content of the treatment fluid. In one or more embodiments
described in the preceding paragraph, wherein the treatment fluid
further comprises one or more solid particulates, and wherein the
method further comprises separating or removing at least a portion
of the solid particulates from the treatment fluid. In one or more
embodiments described in the preceding paragraph, wherein the
portion of the solid particulates is separated or removed from the
base fluid using a separation or removal technique selected from
the group consisting of: settling, decantation, filtration,
centrifugation, dissolving, dissolution, and any combination
thereof.
An embodiment of the present disclosure is a method including:
providing a treatment fluid comprising a base fluid and a polymer,
wherein the treatment fluid was recovered from at least a portion
of a subterranean formation located at a wellsite; transporting the
treatment fluid from the wellsite to an off-site location; and
applying a cavitation technique to at least a portion of the
treatment fluid at the off-site location.
In one or more embodiments described in the preceding paragraph,
wherein applying the cavitation technique to at least the portion
of the treatment fluid comprises using a device selected from the
group consisting of: a hydrodynamic cavitation device, a
centrifugal pump, a marine propeller, a water turbine, an
ultrasonic probe, an ultrasonic horn, an ultrasonic vibrator, an
ultrasonic homogenizer, a flow-through sonication device, and any
combination thereof. In one or more embodiments described in the
preceding paragraph, storing the treatment fluid at the off-site
location. In one or more embodiments described in the preceding
paragraph, wherein the treatment fluid further comprises one or
more solid particulates, and wherein the method further comprises
separating or removing at least a portion of the solid particulates
from the treatment fluid using a separation or removal technique
selected from the group consisting of: settling, decantation,
filtration, centrifugation, dissolving, dissolution, and any
combination thereof. In one or more embodiments described in the
preceding paragraph, wherein the portion of the solid particulates
is separated or removed at the off-site location. In one or more
embodiments described in the preceding paragraph, adding one or
more additives to the treatment fluid after the portion of the
solid particulates has been separated or removed to form a second
treatment fluid; and introducing the second treatment fluid into at
least a portion of the subterranean formation. In one or more
embodiments described in the preceding paragraph, wherein the
additives are added to the treatment fluid at the off-site
location.
Therefore, the present disclosure is well adapted to attain the
ends and advantages mentioned as well as those that are inherent
therein. The particular embodiments disclosed above are
illustrative only, as the present disclosure may be modified and
practiced in different but equivalent manners apparent to those of
ordinary skill in the art having the benefit of the teachings
herein. While numerous changes may be made by those of ordinary
skill in the art, such changes are encompassed within the spirit of
the subject matter defined by the appended claims. Furthermore, no
limitations are intended to the details of construction or design
herein shown, other than as described in the claims below. It is
therefore evident that the particular illustrative embodiments
disclosed above may be altered or modified and all such variations
are considered within the scope and spirit of the present
disclosure. In particular, every range of values (e.g., "from about
a to about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood as referring to the power set (the set of all subsets)
of the respective range of values. The terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee.
* * * * *